Natural gas is an important, global energy and chemical feedstock resource. The term ‘natural gas’ does not specify a uniform substance, but rather is a phrase used to distinguish primarily gaseous hydrocarbon fuels. Different sources have different concentrations of CH4, gas phase hydrocarbons (C2-C5), condensate (C5+ hydrocarbons), inert gases (CO2, N2, Ar), and contaminants such as H2S.
Geography, at least in part, determines the composition of the natural gas resource. Table 1 summarizes some of the differences (Bakar and Ali, 2012 for wells outside of the U.S.; Environment and Energy News, 2012 for N. Dakota Bakken wells, and U.S. Geological Survey, 2013 for New Mexico). These dissimilarities pose a problem, as any distributed (on-site) production of liquid fuels from these sources must be extremely flexible and capable of internal processing adjustment to meet the differing compositions presented.
TABLE 1The Variation in Constituents Typically Found in GaseousHydrocarbon ResourcesU.S.U.S.(North(NewNether-Paiki-SaudiIndo-Dakota)Mexico)landsFrancestanArabianesiaConstituentConcentration (%)1Methane59.374-958169275666Ethane17.7 0-102.93.00.7188.5Propane9.40-50.40.90.39.814.5Butane2.70-30.10.50.34.55.1Pentane+0.92  0-0.50.10.5nd1.60.8CarbonDioxide0.51 0-100.99.346.28.94.1Oxygennd  0-0.2ndndndndndNitrogen7.10-314.31.525.20.21.3Hydrogennd0-1ndndndndndRare Gasesnd0-1ndndndndnd1nd: not determined
Forty to sixty percent of the world's proven gas reserves are stranded (PetroWiki, 2014). They are stranded for one or more of the following reasons:                1. The reserve is too remote from the market for natural gas and natural gas liquids (NGL's), making construction of a major pipeline prohibitively expensive.        2. The reserve is in a region where the demand for gas is saturated, and the cost of exporting gas beyond its production region is excessive.        3. The reserve has a limited production lifetime.        4. In addition to CH4, the resource contains significant concentrations of other gas-phase C2-C4 hydrocarbons, C5+ hydrocarbons (NGLs), inert gases and/or contaminants that make the resource unsuitable for introduction into a gas pipeline. The natural gas received and transported by the major intrastate and interstate mainline transmission systems must meet the quality standards specified by pipeline companies in the “General Terms and Conditions (GTC)” section of their tariffs. These quality standards vary from pipeline to pipeline and are usually a function of a pipeline system's design, its downstream interconnecting pipelines, and its customer base.        5. The current market for NGLs is poor due to overabundance in many regions (Cantrell et al, October 2013).        6. Gas can be an uneconomical by-product of oil production. Since it is not cost-effective to utilize this natural gas due to low gas volumes (typically about 0.1-5.0 million scf/day/well) and since this resource usually declines in volume in a few years, this associated gas is normally flared (burned) during the oil production process (PetroWiki, 2014). This flaring wastes a potentially valuable resource and produces high levels of greenhouse and criteria pollutant emissions. For example, in North Dakota during July 2014, over 12,000,000 Mcf of natural gas was flared representing about one third of the total gas production in the state (reference: North Dakota State Government, “North Dakota Drilling and Production Statistics” (2014).        
The issues above have led to the development of distributed gas-to-liquids (GTL) processes (Sousa-Aquiar et al., 2011). The liquid hydrocarbon products produced from the GTL process can then be economically transported to customers using the existing, liquid fuel transport infrastructure.
The selection of technologies for the distributed conversion of gaseous hydrocarbon resources to fuels is not straightforward, especially in view of the fact that the conversion processes may need to be operated at remote locations and/or at locations where limited infrastructure is available. Major factors to be considered include the cost, volume, composition and lifetime of the gaseous hydrocarbon resource; the compactness and complexity of the conversion process; plant capital and operational and maintenance (O&M) requirements; the ability to move all of the major unit processes to the distributed site using truck transport on the available road infrastructure; the energy efficiency of the plant; air emissions and water effluents; safety; product off-take; and other factors.
To date, the conversion of gaseous hydrocarbon resources into more valuable liquid hydrocarbon products has been comprised of four main unit processes: 1) oxygen generation 2) syngas generation; 3) catalytic conversion of the syngas to intermediate products (primarily wax) and; 4) wax upgrading/refining processes such as hydrocracking and other upgrading/refining steps (Cantrell et al, 2013).
During the oxygen generation step, oxygen is produced from air and is used as an input to the syngas generation process. Several commercial methods can be used for oxygen generation including cryogenic oxygen production plants, pressure swing absorption (PSA) methods, vacuum pressure swing absorption (VPSA) methods, ceramic or other types of membranes, and other oxygen generation technologies. Each of these methods requires substantial capital to deploy. The oxygen is delivered to the syngas unit at different levels of purity depending on the oxygen generation process used. For example, use of a VPSA method will result in 90-93% oxygen with the balance of Argon and Nitrogen. These impurities are sent into the syngas generation plant and then follow through to the other unit processes, reducing efficiency and resulting in higher capital costs to accommodate these gas volumes. One additional challenge of the current technologies for oxygen generation is the requirement for compression of the oxygen, requiring compression capital and operating expense (energy) to compress the oxygen gas up to plant pressure for input into the system.
Since the 1930's, syngas has been used as an important feedstock for producing fuels and chemical products (Arsalanfar, M. et al, 2014). For the efficient production of fuels or chemicals, H2/CO should ideally be within the stoichiometric ratio of about 1.8-2.4/1.0.
Syngas production can use a variety of methods but the most efficient are the ones that use oxygen as an input (oxidant) to the system. Technologies include partial oxidation (PDX) and auto-thermal reforming (ATR).
Partial oxidation (PDX) is carried out with sub-stoichiometric gaseous hydrocarbon/oxygen mixtures in reformers at temperatures in the 1,500-2,700° F. range. Praxair, Shell, ConocoPhillips and others have developed systems for the conversion of gaseous hydrocarbon resources into syngas using PDX. Each of these systems uses an oxygen input, requiring pressurized oxygen to be delivered to the plant using one of the methods described above. The Praxair process as an example utilizes a hot oxygen burner that is non-catalytic and converts natural gas (or other hydrocarbons) and oxygen into syngas as described in U.S. Patent application US2012/037562. ConocoPhillips uses a catalyst in their system as described in U.S. Pat. No. 7,261,751. In commercial practice, some quantity of steam may be added to the PDX reformer in order to minimize elemental carbon formation and increase the H2/CO ratio as described in the U.S. Pat. No. 6,942,839 by Shell.
There are some disadvantages with the use of PDX for smaller distributed gas-to-liquids systems: 1) any PDX process requires oxygen making it necessary to co-locate an oxygen production plant next to the distributed GTL plant and, depending upon the oxygen generation method, may contain concentrations of other gases such as nitrogen and argon; 2) additional unit operations are required to increase the H2/CO to the appropriate stoichiometric ratios of 1.8-2.4 and; 3) nitrogen present in the feedstock or present in the oxygen stream produces NH3 and HCN contaminants in the syngas stream, which are potential catalyst poisons.
Autothermal Reforming (ATR) is another category of technology that utilizes a catalyst to produce syngas from gaseous s hydrocarbons, oxygen, and steam. Shell describes an ATR process in the U.S. patent Ser. No. 08/499,153 and Ballard Power Systems describes an ATR process in U.S. Ser. No. 09/684,170. There are several disadvantages when using ATR in a distributed plant: 1) the catalyst is costly and may have a limited lifetime; 2) the catalytic reformers are large and expensive; 3) an entire co-located oxygen production plant is needed which adds significant capital cost and can more than double the plant energy requirements and; 4) since the H2/CO ratio is too high, additional unit processes are required for the separation of the hydrogen as required to decrease the H2/CO to the required stoichiometric ratio.
Following syngas production, the primary catalysts used for conversion of the syngas to intermediate products include Fischer-Tropsch (F-T) catalysts that produce a mix of hydrocarbon products, mostly focused in the wax range (hydrocarbons from approximately C30 to C100). Many Fischer-Tropsch catalysts and systems are described and are generally known in the art.
For example, U.S. Pat. No. 6,262,131 B1 (Syntroleum), issued Jul. 17, 2001, describes a structured Fischer-Tropsch catalyst system and method that includes at least one structure having a catalytic surface, such catalytic surface having a linear dimension exceeding 20 mm, a void ratio exceeding 0.6, and a contour that causes non-Taylor flow when CO and H2 pass through the structure. F-T catalysts, including iron and cobalt, are described in the patent.
U.S. Pat. No. 7,404,936 (Velocys, Inc.) issued Jul. 29, 2008, describes a micro-channel reactor system and catalysts used in the micro-channel reactor system to produce heavy hydrocarbons (primarily wax) from a syngas steam.
U.S. Pat. No. 4,499,209 (Shell Oil Company), issued Feb. 12, 1985, describes a Fischer-Tropsch catalyst prepared by impregnation of a silica carrier with a solution of zirconium and titanium, followed by calcination and other preparation steps.
U.S. Pat. No. 5,620,670 (Rentech, Inc.) issued Apr. 15, 1997; describe a catalytic process converting hydrogen and carbon monoxide in a Fischer-Tropsch synthesis reactor using promoted iron oxide catalyst slurry.
These patents describe catalysts that form high molecular weight hydrocarbon reaction products (e.g., wax) that require further processing, including hydro-processing and other upgrading processes, to produce diesel fuel or diesel blendstock.
Hydrocracking and other upgrading processes add significant expense and complexity to a plant design. Such processes can be justified for large, refinery scale plants such as traditional gas to liquids plants. However for smaller, distributed applications that require lower volumes of feedstock for gas-to-liquids (GTL), and other plants that function at smaller scale (generally less than approximately 10,000 barrels per day), plant designs that incorporate traditional F-T processes that include hydrocracking and other expensive upgrading processes may not be economically viable.
There are also well know methods of recycling by-product streams produced from integrated syngas production and Fischer Tropsch systems to achieve higher yields.
Information relevant to the recycling of CO2 during the catalytic conversion of syngas to liquid fuels is available in U.S. Pat. No. 6,693,138 (O'Rear, 2004) and U.S. Pat. No. 7,910,629 (Minta et al, 2011). However, these references require that the CO2 be separated from the tailgas in an expensive and cumbersome process.
Information relevant to the recycling of C1-C5 hydrocarbons may be found in Shah et al, 2003 and Schanke et al, 2004. However, none of the related art uses recycled C1-C5 hydrocarbons to maintain an optimum syngas H2/CO ratio of 1.8-2.4.
Information relevant to recycling water with C1-C5 alcohols is available in Pruet, 2005. However, this method requires that these organic compounds be removed before the introduction to the syngas generator.
From the discussion above, it is evident that most distributed natural gas production sites cannot be economically served by current technologies.